Field of the Invention
The present invention relates generally to the field of electric power supply and generation systems and, more particularly, to a system and method for estimating and/or providing dispatchable operating reserve energy capacity for an electric utility using active load management so that the reserve capacity may be made available to the utility or to the general power market (e.g., via a national grid).
Description of Related Art
Energy demand within a utility's service area varies constantly. Such variation in demand can cause undesired fluctuations in line frequency if not timely met. To meet the varying demand, a utility must adjust its supply or capacity (e.g., increase capacity when demand increases and decrease supply when demand decreases). However, because power cannot be economically stored, a utility must regularly either bring new capacity on-line or take existing capacity off-line in an effort to meet demand and maintain frequency. Bringing new capacity online involves using a utility's reserve power, typically called “operating reserve.” A table illustrating a utility's typical energy capacity is shown in FIG. 1. As shown, operating reserve typically includes three types of power: so-called “regulating reserve,” “spinning reserve,” and “non-spinning reserve” or “supplemental reserve.” The various types of operating reserve are discussed in more detail below.
Normal fluctuations in demand, which do not typically affect line frequency, are responded to or accommodated through certain activities, such as by increasing or decreasing an existing generator's output or by adding new generating capacity. Such accommodation is generally referred to as “economic dispatch.” A type of power referred to as “contingency reserve” is additional generating capacity that is available for use as economic dispatch to meet changing (increasing) demand. Contingency reserve consists of two of the types of operating reserve, namely, spinning reserve and non-spinning reserve. Therefore, operating reserve generally consists of regulating reserve and contingency reserve.
As shown in FIG. 1, spinning reserve is additional generating capacity that is already online (e.g., connected to the power system) and, thus, is immediately available or is available within a short period of time after a determined need (e.g., within ten (10) to fifteen (15) minutes, as defined by the applicable North American Electric Reliability Corporation (NERC) regulation). More particularly, in order for contingency reserve to be classified as “spinning reserve,” the reserve power capacity must meet the following criteria:                a) be connected to the grid;        b) be measurable and verifiable; and        c) be capable of fully responding to load typically within 10-15 minutes of being dispatched by a utility, where the time-to-dispatch requirements of the spinning reserve are generally governed by a grid system operator or other regulatory body, such as NERC.        
Non-spinning reserve (also called supplemental reserve) is additional generating capacity that is not online, but is required to respond within the same time period as spinning reserve. Typically, when additional power is needed for use as economic dispatch, a power utility will make use of its spinning reserve before using its non-spinning reserve because (a) the generation methods used to produce spinning reserve capacity typically tend to be cheaper than the methods, such as one-way traditional demand response, used to produce non-spinning reserve or (b) the consumer impact to produce non-spinning reserve is generally less desirable than the options used to produce spinning reserve due to other considerations, such as environmental concerns. For example, spinning reserve may be produced by increasing the torque of rotors for turbines that are already connected to the utility's power grid or by using fuel cells connected to the utility's power grid; whereas, non-spinning reserve may be produced from simply turning off resistive and inductive loads such as heating/cooling systems attached to consumer locations. However, making use of either spinning reserve or non-spinning reserve results in additional costs to the utility because of the costs of fuel, incentives paid to consumers for traditional demand response, maintenance, and so forth.
If demand changes so abruptly and quantifiably as to cause a substantial fluctuation in line frequency within the utility's electric grid, the utility must respond to and correct for the change in line frequency. To do so, utilities typically employ an Automatic Generation Control (AGC) process or subsystem to control the utility's regulating reserve. To determine whether a substantial change in demand has occurred, each utility monitors its Area Control Error (ACE). A utility's ACE is equal to the difference in the scheduled and actual power flows in the utility grid's tie lines plus the difference in the actual and scheduled frequency of the supplied power multiplied by a constant determined from the utility's frequency bias setting. Thus, ACE can be written generally as follows:ACE=(NIA−NIS)+(−10B1)(FA−FS),  [Equation 1]                where                    NIA is the sum of actual power flows on all tie lines,            NIS is the sum of scheduled flows on all tie lines,            B1 is the frequency bias setting for the utility,            FA is the actual line frequency, and            FS is the scheduled line frequency (typically 60 Hz).                        
In view of the foregoing ACE equation, the amount of loading relative to capacity on the tie lines causes the quantity (NIA−NIS) to be either positive or negative. When demand is greater than supply or capacity (i.e., the utility is under-generating or under-supplying), the quantity (NIA−NIS) is negative, which typically causes ACE to be negative. On the other hand, when demand is less than supply, the quantity (NIA−NIS) is positive (i.e., the utility is over-generating or over-supplying), which typically causes ACE to be positive. The amount of demand (e.g., load) or capacity directly affects the quantity (NIA−NIS); thus, ACE is a measure of generation capacity relative to load. Typically, a utility attempts to maintain its ACE very close zero using AGC processes.
If ACE is not maintained close to zero, line frequency can change and cause problems for power consuming devices attached to the electric utility's grid. Ideally, the total amount of power supplied to the utility tie lines must equal the total amount of power consumed through loads (power consuming devices) and transmission line losses at any instant of time. However, in actual power system operations, the total mechanical power supplied by the utility's generators is seldom exactly equal to the total electric power consumed by the loads plus the transmission line losses. When the power supplied and power consumed are not equal, the system either accelerates (e.g., if there is too much power in to the generators) causing the generators to spin faster and hence to increase the line frequency or decelerates (e.g., if there is not enough power into the generators) causing the line frequency to decrease. Thus, variation in line frequency can occur due to excess supply, as well as due to excess demand.
To respond to fluctuations in line frequency using AGC, a utility typically utilizes “regulating reserve,” which is one type of operating reserve as illustrated in FIG. 1. Regulating reserve is used as needed to maintain constant line frequency. Therefore, regulating reserve must be available almost immediately when needed (e.g., in as little as a few seconds to less than about five (5) minutes). Governors are typically incorporated into a utility's generation system to respond to minute-by-minute changes in load by increasing or decreasing the output of individual generators and, thereby, engaging or disengaging, as applicable, the utility's regulating reserve.
The Federal Energy Reliability Commission (FERC) and NERC have proposed the concept of Demand Side Management (DSM) as an additional approach to account for changes in demand. DSM is a method in which a power utility carries out actions to reduce demand during peak periods. Examples of DSM include encouraging energy conservation, modifying prices during peak periods, direct load control, and others.
Current approaches for using DSM to respond to increases in demand have included using one way load switches that interrupt loads, as well as statistics to approximate the average amount of projected load removed by DSM. A statistical approach is employed because of the utility's inability to measure the actual load removed from the grid as a result of a DSM load control event. In addition, current DSM approaches have been limited to use of a single power measuring meter among every one hundred (100) or more service points (e.g., residences and/or businesses). Accordingly, current DSM approaches are inadequate because they rely on statistical trends and sampling, rather than on empirical data, to make projections and measure actual load removal events.
More recently, FERC and NERC have introduced the concept of flexible load-shape programs as a component of DSM. These programs allow customers to make their preferences known to the utility concerning timing and reliability of DSM load control events. However, DSM approaches utilizing load-shaping programs do not meet all of the criteria for implementing regulating reserve or spinning reserve, such as being dispatchable within 15 minutes or less. Additionally, in order for a generating source to be considered dispatchable energy, it must be forecasted twenty-four (24) hours prior to being delivered to a utility. Current DSM approaches do not facilitate accurate forecasting twenty-four (24) hours in advance due to their heavy reliance on statistics.
Therefore, there is a need for utilities to be able to create operating reserve, especially regulating and/or spinning reserve, by using accurate forecasting and flexible load shaping techniques. There is a further need to involve the consumer in a two-way approach in which the consumer can make their energy consumption preferences known and the utility can make use of those preferences to respond to increased demand and maintain line frequency regulation.